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Annual performance review of in-situ oil sands scheme approval 9404W
Pelican Lake Asset Team
Conventional Oil & Gas
Cenovus Energy Inc.
April 6, 2017
2
This presentation contains forward-looking information prepared and submitted pursuant to Alberta regulatory requirements and is not intended to be relied upon for the purpose of making investment decisions, including without limitation, to purchase, hold or sell any securities of Cenovus Energy Inc. Additional information regarding Cenovus Energy Inc. is available at cenovus.com.
Disclaimer
Agenda
• Introductions
• Current approval
• Geological overview
• Scheme performance update
• Water usage update
• Hot water injection update
• Cap rock integrity & monitoring program
• Facilities update
• 2016 development activities
• AER regulatory discussion & key learnings
3
5
• 9404W was originally approved in April 2014
• No near term requirements to expand beyond existing boundaries and spacing
• Pads shown in green are performance examples shown later in presentation
Approval 9404W – Current EOR scheme area
Interwell spacing distance is from producer to producer
7
Geologic review The development interval at Pelican Lake is the Wabiskaw formation
• Wabiskaw and Clearwater are part of the Mannville Group
• Wabiskaw composed of oil bearing shoreface sands
• Clearwater acts as cap rock and is composed of mudstones and very competent calcified siltstones
• Reservoir properties are very consistent and of a high quality across the field
Wabiskaw depositional environment: Prograding shoreface into a shallow sea
• Shallow Sea Prograding Shoreface
Environment, sourced from the Red
Earth and Grosmont Highlands.
• During the early Cretaceous, a relative rise in sea level caused a major southward transgression of the Boreal Sea, which in turn created a marine environment for the deposition of the Wabiskaw Member
• approximately 133 million years ago a shallow sea filled the basin from the north, with the Red Earth & Granor Highlands protruding as barriers
• large extent Tabular sands a result of Shallow sea environment
• these barriers are the primary source of sediment supply for the formation of the Wabiskaw
• The Pelican Lake field is interpreted as a lower to middle shoreface sand which progrades towards the northwest into an offshore environment
10 Date here
Prograding shoreface environment makes the reservoir very uniform, continuous and predictable.
• Net pay bounded by onlap edge to the north and shoreface edge to the south, thinning uniformly from the center of the pool to the edges
Viscosity is low enough for mobile oil over the majority of the pool. However as we approach the edges of the pool the viscosity gradient is very steep.
• Full development inventory lies in the mobile oil area
Structure is driven by Paleozoic unconformity and rises dramatically to the NE.
• A number of gas caps exist on associated highs, mostly in the NE part of the reservoir and are avoided when planning our future development wells
Reservoir properties of the step out areas in both the mobile and hot water development plans compare very favorably to the rest of the field.
Wabiskaw net pay & viscosity fairway
Regional caprock geology: Clearwater and Wabiskaw formation
12
• Top Clearwater to top Wabiskaw porosity includes Clearwater formation, Wabiskaw tight streak and Wabiskaw shale
• 75 to 95 m thick over the oil development area, very gentle dip to the SW
• Clearwater formation can be correlated across entire region
• Clearwater subdivided into four units: three cycles (Clearwater C, B, and A) and a shale unit at the top. The siltstone at the top of the three packages has been cemented into a tight streak or a package of calcareous streaks.
• The Clearwater units and associated packages of tight streaks can be correlated regionally
• The Wabiskaw tight streak is present in every well across the area and can be correlated regionally Clearwater formation deposition is unaffected by karsting or carbonate dissolution. Therefore, Clearwater deposition occurs after these events.
Calcified tight
streaks
(2) (3) (4)
(5) (7) (8) (6)
(1)
Milestones
1) Primary production (400m inter-well spacing)
2) Waterflood pilot (400m inter-well; injector infilled)
3) Commercial Waterflood
4) Polymer pilot
5) Commercial polymer
6) Injection rates lowered to arrest watercut increases. Injection shut-in on pads for infill drilling program
7) Infill drilling to 100m and 133m inter-well spacing (2011-2014)
8) Hot Water pilot (pad E29)
9) Field-wide optimization of injection rates and polymer consumption
14
Scheme 9404W - Production update (cumulative oil @ Dec. 2016 = 23,111 E3m3)
(9) (9)
Milestones
9a) Forest fire near battery caused field to be shut in
9b) Seven day facility turn around
9c) Field wide optimization to bring injection rates in line
15
Scheme 9404W – Production update (cumulative oil @ Dec. 2016 = 23,111 E3m3)
(9a) (9b)
(9c)
Current and expected ultimate recovery factors
16
West: Cumulative pad RF to date = 5.2-22.9%, avg.=15.7% Ultimate PDP pad RF = 7.0–35.5%, avg.=23.0%
Central: Cumulative pad RF to date = 3.6-22.8%, avg. 9.9% Ultimate PDP pad RF = 8.3-35.0%, avg.=14.6%
East: Cumulative pad RF to date = 1.4-18.3%, avg.=7.7% Ultimate PDP pad RF = 4.6–25.5%, avg. =12.2%
• Recovery factors (RF) are dependent on reservoir quality, heterogeneity, pad maturity, well density/spacing, and if gas caps are present
• Cumulative pad recovery factors include primary recovery
17
2016 highlights
Injection rate/polymer consumption optimization
• Continued flood management focus in 2016
• injection rates were reduced to optimize flood performance
• Polymer consumption optimized as supported by technical work
18
SE20 – Good performance
• Dead Oil visc (N-S): 1488-3908 cp
• Waterflood started in 2003
• Polymer started in 2007
• Oil cut started to increase
• Oil rate increased as a result and remains at peak
• Remedial actions in 2015 & 2016 undertaken to heal breakthroughs were met with success
waterflood polymerflood primary
19
NE02 – Average performance
• Dead Oil visc (N-S): 841-636 cp
• Polymer started in late 2010
• Oil decline rate arrested due to improvement in oil cut
• Oil rate stable for the last five years
waterflood polymerflood primary
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SW11 – Below average performance
• Dead Oil visc (N-S): 1950-1478 cp
• Polymer started in 2009
• Insignificant increase in oil cut offset by declining liquid
• No observable upside to polymer
waterflood polymerflood primary Back to winj
Date here 22
Regional hydrogeology
Non-saline water source (polymer make-up)
Saline water source and disposal (Nisku and Grosmont Fm.)
‘A’
‘B’
Date here 23
Water source, observation and disposal well locations
• Grand Rapids formation: hosts non-saline water; source wells usually located at polymer make-up sites • Grand Rapids ‘A’ aquifer: 5 source wells, Grand Rapids ‘B’ aquifer: 21 source wells
• Observations wells: Grand Rapids ‘A’ aquifer: 1, Grand Rapids ‘B’ aquifer: 10 (7 required by licence) • Nisku & Grosmont formations: hosts saline water
• 5 source wells supplement injection volumes to meet well target injection rates; 4 disposal wells
Date here 24
Water quality- Major ions and TDS Durov Plot – Grand Rapids ‘A’ (from 2015 Water Use report) Durov Plot – Grand Rapids ‘B’ (from 2015 Water Use report)
• Grand Rapids ‘A’ and ‘B’ aquifers host Na-HCO3 type water with TDS in the range of 900 to 2,000 mg/L (good for polymer make-up)
Date here 25
2016 non-saline water use summary
Grand Rapids ‘A’
Grand Rapids ‘B’
Total
Annual Licenced Diversion (m3)
341,458 2,783,067 3,124,525
Actual Diversion (m3)
20,816 573,800 594,616
Actual % Licence Used
6.1 20.6 19.0
• Cenovus had 26 licenses that allowed for 3,124,525 m3 of non-saline water usage for polymer injection; two licenses were cancelled in February 2016
• Cenovus used 19% of the total licensed volume; operations scaled back due to the lower price of oil
• Optimization projects are continually executed and evaluated to ensure non-saline water is used to its full benefit for polymer hydration
0.0E+0
5.0E+5
1.0E+6
1.5E+6
2.0E+6
2.5E+6
3.0E+6
3.5E+6
GR A GR B Total
Licensed Diversion (m3/yr)
2016 Actual Diversion (m3/yr)
6.1%
20.6% 19.0%
% Annual Licence Used
Date here 26
Grand Rapids five year water source forecast
• 2017 to 2018 - forecast a modest increase in annual diversion for polymer make-up
• 2019 to 2021 - forecast annual diversion for polymer make-up ~72% of Licensed Diversion
• Additional diversion license requirements dependent on future development
0.0E+0
5.0E+5
1.0E+6
1.5E+6
2.0E+6
2.5E+6
3.0E+6
3.5E+6
2017 2018 2019 2020 2021
Licensed Diversion (m3/yr)
Annual Volume (m3)
32%
54%
72% 72% 72%
% Annual Licence Used
2014 - 2016 total water usage
• Produced water recycle over 98% in 2016
• Reduced Grosmont saline water use in 2015 & 2016 through optimized VRR and reservoir management
• Non-saline Grand Rapids use is effectively managed and mostly used for polymer makeup; non-saline water use was about 11% in 2016
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Key water disposal well: 102/11-07-082-22W4
• Required water disposal rates have remained steady
• 102/11-07 well at Main Battery handled approximately 86% of disposal needs in 2016
2016 annual disposal volume at well 102/11-07: 111,889 m3
Date here 29
Regional groundwater flow model
Period Group Formation Hydro-stratigraphic unit
Model layer
Quaternary/ Tertiary
Undifferentiated Quaternary Till 1-3
Empress (?) Bedrock Valley Deposits
3
Upper Cretaceous
Colorado La Biche Aquitard 4
Viking Aquifer/Aquitard 4-6
Joli Fou Aquitard 6
Lower Cretaceous
Mannville Upper (‘A’) Aquifer/Aquitard 7-10
Lower (‘B’ & “C”) Aquifer/Aquitard 11-13
Clearwater Aquitard N/A
187 km
210 k
m
• Regional groundwater flow model (MODFLOW-2000) supports Wabiskaw EOR scheme 9404W (model developed in 2011)
Date here 30
Model simulations – Drawdown (m) in Grand Rapids ‘A’ and ‘B’
• Purpose: simulate source water production from the Grand Rapids ‘A’ and ‘B’ aquifers to estimate drawdown in both aquifers and to optimize present and future production rates
2
6 8
4
2
4
6
8
Grand Rapids ‘A’ Grand Rapids ‘B’
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From: Figure 14, “Pelican Lake Wabiskaw Enhanced Oil Recovery Project 2015 Annual Water Use Report”
From: Figure 13, “Pelican Lake Wabiskaw Enhanced Oil Recovery Project 2015 Annual Water Use Report”
CVE Grand Rapids Lease Area
CVE Grand Rapids Lease Area
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Annual water use reports
• Previously (<2016) prepared by consultant
• Since 2016, prepared by Cenovus staff
• utilizes in-house expertise
• incorporates internal knowledge, experience, and good working relationships with other operators and lease holders
• integrates Pelican Lake, Wabiskaw and Grand Rapids Pilot learnings
• reflects commitment to responsible water resource management
SE29 (edge and circulation): • 3 horizontal wells
• 1 producer • 2 injectors
• 3 vertical observation wells • Oil viscosity ~ 4000 - 10000 cp
SE28 (edge injection only): • 4 horizontal injectors • Oil viscosity ~ 4000 - 10000 cp
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Pelican Lake hot water injection pilots
• Both pilots target higher oil viscosity areas within Pelican Lake • Expansion opportunities being evaluated offsetting current SE29 pilot
Pilot areas are only hot water (no polymer)
SE29 pilot status update (edge and circulation GR source)
• Phase 1 complete
• primary production: November 28, 2010 - May 31, 2011
• Phase 2 complete
• warm waterflood: June 1, 2011 – March 13, 2012
• Phase 3 ongoing
• hot water circulation (Patent Pending): March 14, 2012 – through January 2015
• boiler facilities shut-in February 2015, pilot underwent cold waterflood and cold water circulation during remainder of 2015
• warm water circulation recommenced in July 2016 (high efficiency line heater)
SE28 pilot status update (edge only produced water)
• Four injectors at SE28 initially targeted a surface injection temperature of 80°C using energy efficient line heaters (max temp 90°C)
• actual injection temperatures remained much lower than target in 2014-2015 due to technical issues with line heaters and fouling, design optimization was completed on one heater with limited success
• pilot was shut-in
Pelican Lake hot water injection status
34 Cenovus proprietary
100 m
SE29
Warm water injection in edge wells Circulate warm water (from toe) in center well and produce (from heel)
Infill producer
Infill water injector
Existing water injector
Observation wells (T, P)
Phase 3: Warm water circulation
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SE29 hot water pilot well configuration
SE29 Hot Water pilot performance • Circulation temperature
entered 2015 at ~160oC prior to being ramped down in February 2015
• Injection rate is representative of total injection from circulation & offsetting injectors
• Oil rates returned to approximately 5m3/d in 2015 after resuming cold waterflood operation, limited impact from cold circulation in Q4-2015
• High efficiency lineheater installed and returned to warm circulation in July 2016
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Primary
Warm WF
Hot WF & Hot Circulation
Cold WF & Cold Circ.
Cold WF & Warm Circ.
Phase 1 Phase 2 Phase 3
Regional Caprock Geology: Clearwater and Wabiskaw Formation
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• Top Clearwater to top Wabiskaw porosity includes Clearwater formation, Wabiskaw tight streak and Wabiskaw shale
• 75 to 95 m thick over the oil development area, very gentle dip to the SW
• Clearwater formation can be correlated across entire region
• Clearwater subdivided into four units: three cycles (Clearwater C, B, and A) and a shale unit at the top. The siltstone at the top of the three packages has been cemented into a tight streak or a package of calcareous streaks.
• The Clearwater units and associated packages of tight streaks can be correlated regionally
• The Wabiskaw tight streak is present in every well across the area and can be correlated regionally
• Clearwater formation deposition is unaffected by karsting or carbonate dissolution. Therefore, Clearwater deposition occurs after these events.
Calcified tight
streaks
Cap rock monitoring summary
No indication of caprock breach based on ongoing flood surveillance
• Previous third-party studies indicate the Clearwater shale caprock is safe against the failure mechanisms studied at injection pressures up to 14 Mpa (bottomhole)
• allowable maximum wellhead injection pressure 7MPa
• Real-time monitoring of Wabiskaw injection pressures and regular review of pattern voidage replacement ratio (VRR)
• injection pressures and VRR’s support containment within the Wabiskaw. Currently, overall VRR=1.1 (instantaneous) with average wellhead injection pressure 4.7 MPa
• using an automated field-wide alarm system in SCADA-ProcessNet to monitor and notify engineers of any changes in injectivity
• long-term monitoring: hall plots
• Real-time monitoring of the bottom hole pressures and rates in Grand Rapids water source wells and bottom hole pressures in Grand Rapids observation wells. No increase in pressures in the Grand Rapids observation wells to suggest any communication with Wabiskaw formation.
Annual water analysis on all Grand Rapids water source wells
• No increases in total dissolved solids (TDS) observed that can be attributed to a loss of caprock integrity
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Observation well summary
Pressure data from observation wells (Wabiskaw & Grand Rapids) indicate no caprock breach occurred in 2016
2014 - 2016 Pelican daily injection volumes
• Injection pressures reduced due to lower water injection volumes
43
Injection pressure: Maximum & average
• Total 525 injection wells
• Allowable maximum wellhead injection pressure = 7,000kPa
• SCADA system logic has alarm and shut-downs set below 7,000KPa
• Average injection pressure fairly constant ~4700 kPa
• Continued annual surveillance of Grand Rapids TDS at the source wells
• No deviation from TDS baseline through time (calculated TDS)
• Exceeding annual monitoring requirements
Grand Rapids water source well TDS tracking
44
Date here 46
Casing Failure Prevention Program Update • Initial program identified 55 High Risk wells identified based on casing
rated collapse pressure, offsetting downhole injection pressure, dogleg severity, offsetting PV polymer injected and proximity to breakthrough
• Program consisted of installation of a liner extension or “stacked liner” to cover area of expected failure within zone
• Only 10 wells remaining from initial program
• Injection pressures have been trending down as injected volumes have been reduced. This has lowered the risk rating on the remaining wells in the original program to a level where we do not plan on proactively installing stacked liners
• Casing failures on wells outside of program have also been trending down with injection rate and pressure
• Sufficient capital in place to react and repair casing failures as they are identified
Casing Failure Prevention Program Update • Casing failures on wells outside of program have also been
trending down with lowering injection rates and pressures
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R23 R18 R19 R20 R21 R22
T82
T81
T83
T84
T82
T84
Cenovus Land
Grosmont Source Water Wells 11-07 Battery Site Midfield Separators
13-11 Satellite
SE10.5 Satellite
11-07 South Battery
Pelican Lake facilities map
50
13-11 Satellite
• Utilizes two inclined free water knock out vessels (cold) to remove as much free water as possible from
emulsion before sending to South Battery for processing
• Free water is pumped into high pressure injection line
SE10.5 Satellite
• Utilizes one inclined free water knock out vessel (cold) to remove as much free water as possible from
emulsion before sending to South Battery for processing (suspended in 2016)
• Free water is pumped into high pressure injection line (suspended in 2016)
11-07 South Battery
• Utilizes inclined free water knock out (cold), heated knock out vessels, plate and frame heat exchangers,
and five treaters to dewater emulsion to sales oil spec.
• De-oiled water is pumped into high pressure injection line
Pelican Lake major facilities description
Date here 51
2016 Facility modifications
• South Battery plate and frame heat exchangers were upgraded (material upgrade from titanium to SMO254 super austenitic stainless steel) to improve reliability
• SE10.5 satellite was suspended as a result of the lower total fluid rates. Equipment suspended includes: inclined free water knockout, water tanks, skim pumps, and water injection pumps. The emulsion transfer pumps remain active. All suspended equipment and associated piping were preserved for future reactivation.
• No major facility modifications are planned for 2017
Date here 54
2016 facility performance
With our optimization of water injection and polymer consumption from 2015 to 2016, all three major facilities had experienced better emulsion separation and water treatment performance:
• Achieved better emulsion separation efficiency at the vessels and also increased the run time of the plate & frame heat exchangers
• Achieved better water treatment performance at the cascading water tanks (through gravity separation and skim system). The oil & grease content in our produced water has dropped from 2015 to 2016.
55
• NE69 to NE63 bare steel emulsion pipeline replacement
• Pipeline cathodic protection upgrade (new anode beds) for the SE28, NE23 and NE69 legs
• Water injection riser replacement
• NE63 to NE69 & South Battery to SW35.5
• Emulsion riser replacement
• SW45 to SW16.5 & South Battery to SW35.5
• Miscellaneous emulsion pig barrel replacement
• Continued with proactive emulsion pipeline improvement program (e.g. conduct linalog inspections and verification digs)
2016 pipeline upgrades
Pelican Lake corrosion mitigation summary
Emulsion Pipeline Legend
Green – Liner Installed
Red – Bare Steel
Emulsion pipeline liner pull/replacement – 95% complete Emulsion pad piping replacement – 85% complete Injection pad piping replacement – 84% complete Injection riser replacement – 98% complete Major facility piping replacement – ongoing Replacement scope is identified by on-going NDE inspections (linalog, verification digs, GW, UT, etc) and risk assessment.
Currently discontinued - will not be in operation until liners are installed
13-11 Satellite
SE10.5 Satellite
11-07 South Battery
Replacement completed in 2016
• The 2016 Corrosion Mitigation budget was never cut nor trimmed even during the economic downturn
57
Power consumption
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2016 Total
Power Import (kWh) 676,657 614,091 605,294 521,875 388,690 355,904 392,507 407,981 255,843 472,968 494,411 609,949 5,796,170
Power Export (kWh) 0 0 0 0 0 0 0 0 0 0 0 0 0
Power Consumption (kWh) 676,657 614,091 605,294 521,875 388,690 355,904 392,507 407,981 255,843 472,968 494,411 609,949 5,796,170
Power Import (kWh) 388,646 363,929 328,711 321,754 71,516 16,887 19,024 18,418 29,283 88,648 94,243 147,100 1,888,159
Power Export (kWh) 0 0 0 0 0 0 0 0 0 0 0 0 0
Power Consumption (kWh) 388,646 363,929 328,711 321,754 71,516 16,887 19,024 18,418 29,283 88,648 94,243 147,100 1,888,159
Power Import (kWh) 2,109,141 1,783,728 1,806,993 1,814,357 1,736,986 1,494,599 1,727,728 1,672,857 1,473,755 1,905,766 1,928,217 2,155,632 21,609,758
Power Export (kWh) 0 0 0 0 0 0 0 0 0 0 0 0 0
Power Consumption (kWh) 2,109,141 1,783,728 1,806,993 1,814,357 1,736,986 1,494,599 1,727,728 1,672,857 1,473,755 1,905,766 1,928,217 2,155,632 21,609,758
Power Import (kWh) 12,102,516 10,477,747 10,442,002 8,981,418 6,373,561 4,831,727 5,207,998 5,597,036 5,917,194 8,678,415 9,426,250 10,538,333 98,574,197
Power Export (kWh) 0 0 0 0 0 0 0 0 0 0 0 0 0
Power Consumption (kWh) 12,102,516 10,477,747 10,442,002 8,981,418 6,373,561 4,831,727 5,207,998 5,597,036 5,917,194 8,678,415 9,426,250 10,538,333 98,574,197
13-11 Satellite
SE10.5 Satellite
11-07 South Battery
2016
Pelican Lake Total
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Gas volumes summary
2017
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2016 Total Jan
Fuel Consumed(e3m3) 1,681 1,422 1,568 1,541 2,122 2,814 1,777 1,637 1,502 1,737 1,657 1,653 21,109 1,663
Produced Gas (e3m3) 1,098 942 1,064 1,090 1,643 2,353 1,289 1,206 1,081 1,224 1,129 1,070 15,189 1,024
Buyback Gas (e3m3) 876 765 832 751 749 673 753 700 682 793 789 861 9,226 771
Vented Gas (e3m3) 227 226 263 243 259 207 261 261 195 252 218 216 2,828 200
Flare (e3m3) 31 30 41 43 4 1 0 0 13 16 28 34 242 26
Solution Gas Recovery Percentage 77% 73% 71% 74% 84% 91% 80% 78% 81% 78% 78% 77% N/A 78%
2016
59
Green house gas emissions summary
2017
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2016 Total Jan
Green House Gas Emissions
(Tonnes CO2 Equivalent) 7,190.93 6,590.06 7,515.99 7,100.84 8,489.32 9,014.00 7,900.73 7,682.35 6,206.24 7,626.97 6,940.72 6,736.80 88,995 6,643
2016
• Vapor recovery units (VRUs) installed on production tanks (no routine gas venting off tanks)
• Air compressors (‘instrument air’) installed for operating pneumatic equipment (no gas venting)
• The still column vent of the 11-07 South Battery Glycol dehydrator was tied in to low pressure flare (vent gas is combusted, not vented to atmosphere)
• Gas conserved on pads where economically feasible
• 2016 total greenhouse gas emissions: 88,995 tonnes CO2 equivalent (20% decrease compared to 2015)
60
Methods of measurement
• Oil and water: inline meters installed on every producer and injector
• Solution gas:
• conserved wells use a facility level gas oil ratio (GOR)
• non-conserved wells use individual GOR as per Dir. 017 requirements
Proration factors
• Within acceptable range (Oil: 0.91, Water: 0.91)
Typical well testing:
• Frequency and duration; all producers have inline metering and are considered on “Test” for full monthly hours
• No test tanks on any wells
Measurement technology:
• Producer: mixture of coriolis and positive displacement meters
• Injector: coriolis meters
Measuring & reporting protocol
Date here 61
• Late submission of Water Use Report under Temporary Diversion License (TDL) 00366686. This was self-disclosed in February 2016 and corrective actions have since been implemented.
• Groundwater was diverted from a well between the expiry of TDL No. 00340416 on November 14, 2014 and the effective date of TDL No. 00360875 on December 3, 2014. This was self-disclosed in February 2016 and corrective actions have since been implemented.
• Exceeded permitted diversion volume for Water Act license 00385580. This was self-disclosed in November 2016 and corrective actions have since been implemented.
Environmental compliance issues summary
Regional environmental initiatives
Member - Regional Industry Caribou Collaboration (RICC)
• Coordination of caribou research and mitigation at the landscape (caribou range) scale
• Coordination of habitat restoration and population research
• Covers the East Side Athabasca and Cold Lake ranges
Cenovus Caribou Habitat Restoration Project
• Habitat restoration within the Cold Lake range
• Covers approximately 3900 km2 of area during 2016-2026
• See http://www.cenovus.com/news/docs/Cenovus-caribou-project-factsheet.pdf for more details
Reclamation program update
• Reclamation is currently under way on approximately 70 locations
• Activities include the following stages: Phase I & II environmental site assessment (ESA), minor soils work or re-contouring, vegetation monitoring and weed control and detail site assessment (DSA)
• Remediation & risk assessment on two sites
• Submitted four reclamation certificate applications in 2016 and received 38 approvals (which were submitted in 2015)
• Target to apply for 20 reclamation certificates in 2017
• Four new abandonments took place in January 2017
Date here 64
• Pelican Lake is currently compliant with all conditions of the approval and regulatory requirements
• Besides the self-disclosures as mentioned under the environmental section, an AER pipeline permit amendment self-disclosure was submitted and approved in March 2016 to update the status of the water injection pipeline Lic#38717 Line#15 from “operating” to “discontinued”. This license discrepancy was identified in our internal annual pipeline risk assessment.
• The Pelican Lake measurement & volumetric reporting was audited in 2016 as part of Cenovus’s Enhanced Production Audit Program (EPAP) as mandated under AER directive 076
Compliance confirmation
Date here 65
• Continue conducting NDE inspections and risk assessment, and upgrade bare steel piping as part of the corrosion mitigation program. AER pipeline permit will be required in the event of a liner pull and/or pipeline replacement.
Future facilities plan
67
• No drilling in 2016
• 2016 priorities:
• operating cost reductions
• optimizing injection rates, non-saline water usage and polymer consumption
• reservoir flood management
• optimize polymer effectiveness
• workover frequency reductions
• Continued reservoir characterization to enhance long term field development strategy
2016 development initiatives
• Current approval and downspacing is flexible for Cenovus to continue its infill program
• Cenovus is in compliance with all conditions of the approval and regulatory requirements
AER regulatory discussion & compliance
69
70
• Reservoir flood optimization is key to maximizing oil recovery
• optimal VRR assists in maximizing recovery by reducing premature
breakthroughs
• maximizing polymer efficiency assists in providing optimal oil
recovery
Key learnings
Date here 74
Se10.5 satellite plot plan
2016 suspended equipment includes inclined free water knockout, water tanks, skim pumps, and water injection pumps. The emulsion transfer pumps remain active.
Date here 75
Facility: SE10.5 satellite process flow
2016 suspended equipment includes inclined free water knockout, water tanks, skim pumps, and water injection pumps. The emulsion transfer pumps remain active.
Date here 76
Facility: SE10.5 satellite process flow
2016 suspended equipment includes inclined free water knockout, water tanks, skim pumps, and water injection pumps. The emulsion transfer pumps remain active.
Date here 77
Facility: SE10.5 Satellite Process Flow
2016 suspended equipment includes inclined free water knockout, water tanks, skim pumps, and water injection pumps. The emulsion transfer pumps remain active.
Date here 80
11-07 South Battery process flow
Upgraded the E-561 plate & frame heat exchangers in 2016